Oil shale is a low permeability rock that contains organic matter primarily in the form of kerogen, a geologic predecessor to oil and gas. Enormous amounts of oil shale are known to exist throughout the world. Particularly rich and widespread deposits exist in the Colorado area of the United States. A good review of this resource and the attempts to unlock it is given in Oil Shale Technical Handbook, P. Nowacki (ed.), Noyes Data Corp. (1981). Attempts to produce oil shale have primarily focused on mining and surface retorting. Mining and surface retorts however require complex facilities and are labor intensive. Moreover, these approaches are burdened with high costs to deal with spent shale in an environmentally acceptable manner. As a result, these methods never proved competitive with open-market oil despite much effort in the 1960's-80's.
To overcome the limitations of mining and surface retort methods, a number of in situ methods have been proposed. These methods involve the injection of heat and/or solvent into a subsurface oil shale, in which permeability has been created if it does not occur naturally in the target zone. Heating methods include hot gas injection (e.g., flue gas, methane—see U.S. Pat. No. 3,241,611 to J. L. Dougan—or superheated steam), electric resistive heating, dielectric heating, or oxidant injection to support in situ combustion (see U.S. Pat. No. 3,400,762 to D. W. Peacock et al. and U.S. Pat. No. 3,468,376 to M. L. Slusser et al.). Permeability generation methods include mining, rubblization, hydraulic fracturing (see U.S. Pat. No. 3,513,914 to J. V. Vogel), explosive fracturing (U.S. Pat. No. 1,422,204 to W. W. Hoover et al.), heat fracturing (U.S. Pat. No. 3,284,281 to R. W. Thomas), steam fracturing (U.S. Pat. No. 2,952,450 to H. Purre), and/or multiple wellbores. These and other previously proposed in situ methods have never proven economic due to insufficient heat input (e.g., hot gas injection), inefficient heat transfer (e.g., radial heat transfer from wellbores), inherently high cost (e.g., electrical methods), and/or poor control over fracture and flow distribution (e.g., explosively formed fracture networks and in situ combustion).
Barnes and Ellington attempt to take a realistic look at the economics of in situ retorting of oil shale in the scenario in which hot gas is injected into constructed vertical fractures. (Quarterly of the Colorado School of Mines 63, 83-108 (October, 1968). They believe the limiting factor is heat transfer to the formation, and more specifically the area of the contact surfaces through which the heat is transferred. They conclude that an arrangement of parallel vertical fractures is uneconomic, even though superior to horizontal fractures or radial heating from well bores.
Previously proposed in situ methods have almost exclusively focused on shallow resources, where any constructed fractures will be horizontal because of the small downward pressure exerted by the thin overburden layer. Liquid or dense gas heating mediums are largely ruled out for shallow resources since at reasonably fast pyrolysis temperatures (>˜270° C.) the necessary pressures to have a liquid or dense gas are above the fracture pressures. Injection of any vapor which behaves nearly as an ideal gas is a poor heating medium. For an ideal gas, increasing temperature proportionately decreases density so that the total heat per unit volume injected remains essentially unchanged. However, U.S. Pat. No. 3,515,213 to M. Prats, and the Barnes and Ellington paper consider constructing vertical fractures, which implies deep reserves. Neither of these references, however, teaches the desirability of maximizing the volumetric heat capacity of the injected fluid as disclosed in the present invention. Prats teaches that it is preferable to use an oil-soluble fluid that is effective at extracting organic components whereas Barnes and Ellington indicate the desirability of injecting superhot (˜2000° F.) gases.
Perhaps closest to the present invention is the Prats patent, which describes in general terms an in situ shale oil maturation method utilizing a dual-completed vertical well to circulate steam, “volatile oil shale hydrocarbons”, or predominately aromatic hydrocarbons up to 600° F. (315° C.) through a vertical fracture. Moreover, Prats indicates the desirability that the fluid be “pumpable” at temperatures of 400-600° F. However, he describes neither operational details nor field-wide implementation details, which are key to economic and optimal practice. Indeed, Prats indicates use of such a design is less preferable than one which circulates the fluid through a permeability section of a formation between two wells.
In U.S. Pat. No. 2,813,583 to J. W. Marx et al., a method is described for recovering immobile hydrocarbons via circulating steam through horizontal propped fractures to heat to 400-750° F. The horizontal fractures are formed between two vertical wells. Use of nonaqueous heating is described but temperatures of 800-1000° F. are indicated as necessary and thus steam or hot water is indicated as preferred. No discussion is given to the inorganic scale and formation dissolution issues associated with the use of water, which can be avoided by the use of a hydrocarbon heating fluid as disclosed in the present invention.
In U.S. Pat. No. 3,358,756 to J. V. Vogel, a method similar to Marx's is described for recovering immobile hydrocarbons via hot circulation through horizontal fractures between wells. Vogel recommends using hot benzene injected at ˜950° F. and recovered at least ˜650° F. Benzene however is a reasonably expensive substance which would probably need to be purchased as opposed to being extracted from the generated hydrocarbons. Thus, even low losses in separating the sales product from the benzene, i.e., low levels of benzene left in the sales product, could be unacceptable. The means for high-quality and cost effective separation of the benzene from the produced fluids is not described.
In U.S. Pat. No. 4,886,118 to Van Meurs et al., a method is described for in situ production of shale oil using wellbore heaters at temperatures >600° C. The patent describes how the heating and formation of oil and gas leads to generation of permeability in the originally impermeable oil shale. Unlike the present invention, wellbore heaters provide heat to only a limited surface (i.e. the surface of the well) and hence very high temperatures and tight well spacings are required to inject sufficient thermal energy into the formation for reasonably rapid maturation. The high local temperatures prevent producing oil from the heating injecting wells and hence separate sets of production-only wells are needed. The concepts of the Van Meurs patent are expanded in U.S. Pat. No. 6,581,684 to S. L. Wellington et al. Neither patent advocates heating via hot fluid circulation through fractures.
Several sources discuss optimizing the in situ retort conditions to obtain oil and gas products with preferred compositions. An early but extensive reference is the Ph.D. Thesis of D. J. Johnson (Decomposition Studies of Oil Shale, University of Utah (1966)), a summary of which can be found in the journal article “Direct Production of a Low Pour Point High Gravity Shale Oil”, I&EC Product Research and Development, 6(1), 52-59 (1967). Among other findings Johnson found that increasing pressure reduces sulfur content of the produced oil. High sulfur is a key debit to the value of oil. Similar results were later described in the literature by A. K. Burnham and M. F. Singleton (“High-Pressure Pyrolysis of Green River Oil Shale” in Geochemistry and Chemistry of Oil Shales: ACS Symposium Series (1983)). Most recently, U.S. Pat. No. 6,581,684 to S. L. Wellington et al. gives correlations for oil quality as a function of temperature and pressure. These correlations suggest modest dependence on pressure at low pressures (<˜300 psia) but much less dependence at higher pressures. Thus, at the higher pressures preferred for the present invention, pressure control essentially has no impact on sulfur percentage, according to Wellington. Wellington primarily contemplates borehole heating of the shale.
Production of oil and gas from kerogen-containing rocks such as oil shales presents three problems. First, the kerogen must be converted to oil and gas that can flow. Conversion is accomplished by supplying sufficient heat to cause pyrolysis to occur within a reasonable time over a sizeable region. Second, permeability must be created in the kerogen-containing rocks, which may have very low permeability. And third, the spent rock must not pose an undue environmental or economic burden. The present invention provides a method that economically addresses all of these issues.